The present application relates to methods and compositions employed during various stages of oil recovery from subterranean formations, and more specifically to the use of chlorine dioxide in operations conducted throughout the lifespan of an oil-bearing formation.
Over the course of the oil recovery cycle from an oil-bearing formation, various operations are performed to facilitate and increase oil recovery. At the front end of the oil recovery cycle, access to oil-bearing strata may involve increasing the permeability of the formation through fracturing. In general, such treatments may be conducted by injecting a liquid, gas, or two-phase fluid down the wellbore at sufficient pressure and flow rate to fracture the subterranean formation. A proppant material, such as sand, fine gravel, sintered bauxite, glass beads, or the like, may also be introduced into the fractures to keep the fractures open after the fracturing pressure is released. Propped fractures provide larger flow channels through which an increased quantity of a hydrocarbon may flow, thereby increasing the productivity rate of the well. Fracturing fluids may employ polymer gel materials to enhance fluid viscosity to aid, inter alia, proppant transport, adequate fracture propagation while maintaining sufficient fracture width to admit proppant, and to reduce the leakage rate of the fracturing fluid into the formation.
Because fracturing operations generally employ large volumes of water it may be desirable, and even environmentally prudent, to employ any produced water, i.e. recovered water already present in the formation. Other produced waters that may be used include recycled water sources, such as waste water, and water from mining operations and landfill leachate. However, the use of produced water has been problematic due the presence of contaminants which can impede the performance of the polymer gels and viscosity reducers that are used in fracturing fluids. Many techniques have been developed to treat produced water so that it can be used to formulate a competent fracturing fluid including nano-filtration, electrocoagulation, and conventional filtration. These techniques tend to be costly and may present practical limitations due to their low throughput. For example, filtration rates may be so limited that there is an insufficient supply for continuous fracturing rates absent storing large volumes of fluid.
At the back end of the oil recovery cycle, operations have been developed to increase the life span of well productivity. To maximize the recovery of hydrocarbons from a reservoir, several methods may be implemented after the natural depletion stage is over. Secondary methods may comprise water or gas injection to help maintain reservoir pressure and ensure hydrocarbon flow to the production wells. The recovery factor after employing secondary methods often remains below 40% of the oil originally in place. At this point tertiary oil recovery methods may then be employed to reach recovery factors above 60%.
Polymer flooding is one such tertiary method (though it may be employed earlier in the oil recovery cycle) applicable over a wide range of reservoir conditions. In polymer flooding, a water-soluble polymer is dissolved in water to increase fluid viscosity typically forming a polymer gel which is introduced into the formation as a “slug,” or continuously. The goal of introducing the polymer is to improve the sweep efficiency through the hydrocarbon reservoir while increasing production fluid to the wellbore. In a typical polymer flood, polymer is mixed and injected over an extended period of time until at least about 30% of the reservoir pore volume has been injected. When using a polymer gel as a slug it is typically followed by water flooding to drive the polymer gel and the oil bank in front of it toward the production wellbore. Alternatively the polymer can be fed continuously to maintain viscosity in the injection fluid to increase sweep efficiency. As with fracturing, the volumes of fluids employed make it desirable to re-use the aqueous portion recovered from the flooding process. However, the exposure of the polymer to the formation can sufficiently chemically alter the polymer making viscosity adjustment of the recovered aqueous fluids both necessary and material intensive, reducing the attractiveness of recycling the water phase in a cyclic flooding process. A further issue in a cyclic flooding process arises with recycling of the polymer. Typically, the polymer ages as it passes through the formation and such aging can cause the polymer to gain an affinity for hydrocarbons, making the separation of hydrocarbons from the polymer-laden fluid difficult.
Still further issues arise under certain formation conditions whereby the polymer can inhibit flow through the formation via polymer plugging of the injection wells, the formation, or both. One means to address polymer plugging employs concentrated chlorine dioxide solution to degrade the polymer. Other oxidants such as hydrogen peroxide, sodium persulfate, sodium hypochlorite, sodium peroxide, and sodium perborate have also been used for this purpose. Polymer plugging notwithstanding, typically the bulk polymer gel slug “breaks through” to the producing wells in a short period of time. The polymer gel may then be brought to the surface as part of the produced fluids. Typically the polymer gel is incorporated in an emulsion phase and a water phase of the produced fluids. While polymer gel capture in the produced fluids may be beneficial from the perspective of maintaining formation integrity, the presence of the polymer in production fluid can hamper separation of water and hydrocarbon. Additionally, the polymer gel present in produced fluids can plate out on production equipment, or “bake” on heater treater surfaces requiring its manual removal.